Process for optimizing removal of condensable components from a fluid

ABSTRACT

A method for removing condensable components from a fluid containing condensable components. The method involves optimizing the temperature of an initial feed stream including the condensable components through heat exchange and cooling to condense liquids there from. The liquids are removed to form a gas stream which is then compressed and after-cooled to form a high pressure stream. A portion of the high pressure stream is expanded to form a cooled low pressure stream which is mixed with the initial feed stream to augment cooling and condensation of condensable components in the initial feed stream.

TECHNICAL FIELD

The present invention relates to the removal of condensables from fluidmixtures exhibiting a positive Joule-Thomson effect, and moreparticularly the present invention relates to the removal of, forexample, water from acid gas streams, for minimizing or substantiallyeliminating the formation of liquid water therein so as to minimizecorrosion and formation of hydrates in the gas stream, transported andinjected for sequestration. A discussion of retrofit and enhancedhydrocarbon recovery is also provided.

BACKGROUND ART

Gas streams, such as those which result from petroleum processing orcombustion processes, often contain a gas or gases which form an acidwhen mixed with water. Such gases are typically called “acid gases”. Themost common naturally occurring acid gases resulting from petroleumprocessing are hydrogen sulfide (H₂S) and carbon dioxide (CO₂). Typicalacid gases derived from combustion/oxidation/pyrolysis processes arecarbon dioxide (CO₂), sulphur dioxide (SO₂), and nitrogen oxides (NO,NO₂).

Acid gases typically contain water. Naturally occurring acid gases areoften saturated with water in the reservoir and combustion-derived gasesco-exist with the water formed from the reaction of hydrogen and oxygenduring combustion. Virtually all acid gases eventually end up beingsaturated with water vapour at some point during the process of removalor purification of the acid gas. Reducing the temperature or increasingthe pressure, over a defined range, of an acid gas containing water,such as that which occurs when the acid gas is passed through acompressor, will result in the condensing of some of the water from agas to a liquid phase. At some temperature, still above the freezingpoint of water, the water and acid gas may begin to firm a “solid like”structure called a gas hydrate. The temperature at which hydrates maybegin to form is called the Hydrate Formation Temperature (HFT) whichvaries according to the pressure, composition and water content of themixture. Hydrates are the physical combination of water and smallmolecules producing a compound having an “ice like” appearance, butpossessing different properties and structure than ice. Hydrates mayalso be known as gas clathrate. Hydrates are problematic as they cancause reduced heat transfer, excess pressure drops, blockages,interruptions in production and are a safety concern.

The formation of an aqueous phase in any gas system is undesirable as itpromotes corrosion, can cause gas hydrates to form and can causemechanical and operational problems. An aqueous phase is particularlyundesirable in an acid gas system as the resulting aqueous phase will beacidic, resulting in a significant increase in the corrosion rate andusually resulting in a higher HFT than non-acid gases.

Table A illustrates the levels of corrosion which occur in mild steel atvarying concentrations of acid gas components in water.

TABLE A Corrosion of Mild Steel by Carbon Dioxide and Other Gases inWater* 0₂ conc. H₂S conc. Corrosion mils/yr Corrosion mils/yr ppm ppmCO₂ conc, 200 ppm CO₂ conc, 600 ppm 8.8 0 28 60 4.3 0 18 44 1.6 0 12 340.4 0 17 27 <0.5 35 6 6 <0.5 150 15 16 <0.5 400 17 21 *Temperature 80°F., exposure 72 hr. Source: Data of Watkins and Kincheloe (1958) andWatkins and Wright (1953)

Although the discussion has focused on acid gas, it will be appreciatedby those skilled that the methodology and concept is applicable forremoving condensable components from any fluid stream exhibiting apositive Joule-Thomson coefficient.

SUMMARY OF THE INVENTION

One object of one embodiment of the present invention is to provide amethod for removing condensable components from a fluid containing saidcondensable components, comprising: optimizing the temperature of aninitial feed stream including said condensable components through heatexchange and cooling to condense liquids there from and removing saidliquids to form a gas stream; compressing and after-cooling said gasstream to form a high pressure stream; expanding at least a portion ofsaid high pressure stream to form a cooled low pressure stream andmixing said cooled low pressure stream with said initial feed stream toaugment cooling and condensation of condensable components in saidinitial feed stream.

Having reference to FIGS. 1 and 2, water content in an acid gas isproportional to temperature and up to about 400 psia for H₂S and 900psia for CO₂, is inversely proportional to pressure. Within theselimits, higher pressures and lower temperatures favor low water contentin acid gases.

Dehydration is the process of removing water so as to minimize orprevent hydrate and free water formation. In an acid gas with arelatively high H₂S concentration, sufficient water is typically removedduring cooling between stages of conventional multi-stage compressionthrough to dense phase (some pressure above the critical pressure of thefluid also known as super critical) such that a separate dehydrationprocess is not required. As the CO₂ content of the acid gas increases,sufficient water removal through compression alone becomes less likelyand a separate dehydration process is usually required.

Conventional means of gas dehydration are solid desiccant adsorption,liquid desiccant absorption, refrigeration, membrane separation, and drygas stripping. The most commonly used methods are solid desiccantadsorption and liquid desiccant absorption.

Glycol dehydration, a liquid desiccant absorption process, is generallyregarded as the favored operational and most economical for mostapplications. Such liquid desiccant dehydration processes have severaldrawbacks:

-   -   glycol losses in a high pressure CO₂ service can be significant;    -   excess oxygen, typically found in combustion-formed acid gases        significantly increases corrosion and accelerates the        degradation of the glycol at higher regeneration temperatures,        necessitating the addition of continuous glycol reclamation        process;    -   glycol must be monitored and treated to maintain a proper pH        range;    -   dehydration equipment is typically manufactured from high cost,    -   corrosion resistant metals such as stainless steel to handle the        acidic liquids produced;    -   glycol is typically heated to temperatures up to 400° F. for        regeneration resulting in vaporizing of water and venting the        absorbed acid gases to atmosphere and any other contaminants        also absorbed by the glycol, such as volatile organic compounds        (VOC's), typically benzene, toluene, ethyl benzene and xylene        (BTEX) and any stripping gases. Control of these fugitive        emissions generally requires the addition of costly vapor        recovery equipment and introduces the potential for further        oxygen contamination;    -   utility requirements of such processes are high and include the        fuel used for glycol regeneration and the power required to pump        the glycol and operate the vapor recovery equipment;    -   significant total carbon footprint is generated as a result of        the manufacturing of the dehydration equipment, and the CO₂        produced from the utility demands of the system and of the        formulation of the glycol used in the dehydration process.

Dehydration by refrigeration makes use of a gas's reduced ability tohold water as it's temperature is decreased. Temperature reduction canbe achieved indirectly by heat exchange from external ‘refrigeration’ orother temperature reduction process, or directly by expansion of the gasitself. Direct expansion of the gas is either isentropic expansion suchas in a turbo-expander or isenthalpic expansion, such as through aJoule-Thomson (JT) valve used in a conventional choke plant or through agas compression refrigeration process. Installing a dedicated indirectrefrigeration unit solely for the purpose of dehydration is typicallycost prohibitive.

Both direct isenthalpic and isentropic refrigeration dehydration methodsutilize an expansion device, a low temperature separator and at leastone heat exchanger to recover as much energy from the process aspossible. In their simplest form, the entirety of the gas is expanded,either isenthalpically or isentropically, from a higher pressure to alower pressure, resulting in a fluid temperature low enough for watercondensation to occur. The condensed water is removed from the processin a low temperature separator and the residual low temperature,substantially dry gas is used to pre-cool incoming fluid to improve thethermal efficiency of the process. This is typically referred to as a“Choke Plant” or “Dew Point Control Unit (DPCU)” in an upstream oil andgas processing application.

In the isentropic expansion case, expansion is accomplished with anexpander and the work extracted by the expander is typically used topartially recompress the outlet dry gas.

The choice of whether to use isentropic or isenthalpic expansion isdependent upon the amount of water removal required, and therefore theamount of temperature reduction required. Isentropic expansion iscapable of achieving lower temperatures. From a capital costperspective, the isentropic process is significantly more costly, butthe ability to recover work has an offsetting advantage. From anoperation and maintenance perspective, the isenthalpic process has anadvantage of being mechanically and operationally simple and suitablefor most applications. The offsetting disadvantage of the isenthalpicprocess is the requirement to consume additional work through increasedcompression requirements.

The common drawback of any of the refrigeration dehydration processes isthat most applications require the gas stream to be cooled to atemperature that is near or below the hydrate formation temperature(HFT) to achieve the desired level of dehydration. For reliableoperation, continuous addition of a thermodynamic hydrate inhibitor,such as glycol or methanol, is usually employed to lower the HFT. Ifdesired, both glycol and methanol are recoverable but require a separateregeneration process complete with all of the issues discussed earlierunder liquid desiccant dehydration. Often the choice is made to usemethanol without recovery as methanol is relatively benign and has lessimpact on downstream processes than glycol although this choicetypically results in a higher operating cost. Interestingly, methanolnot only is useful as the hydrate inhibitor, but also reduces the watercontent further than simple temperature reduction. In this manner, thereis enhanced dehydration.

Clearly there is a need for a dehydration process for acid gas streamsthat is efficient and cost effective and which avoids the problems notedwith conventional dehydration processes.

BRIEF DESCRIPTION OF THE DRAWINGS

The features of the invention will become more apparent in the followingdetailed description in which reference is made to the appended drawingswherein:

FIG. 1 is a graphical illustration of the saturated water content ofvarious fluids, acid gases and methane (CH₄) at 100° F. over a range ofpressures;

FIG. 2 is a graphical illustration of the saturated water content ofCO₂-rich mixtures and methane (CH₄) at 100° F. over a range ofpressures;

FIG. 3 is a graphical illustration of the glycol losses in a prior arthigh pressure CO₂ service;

FIG. 4A is a schematic of an isenthalpic dehydration process accordingto an embodiment of the invention for a water saturated fluid streamcomprising 100% CO₂;

FIG. 4B is a schematic of an isenthalpic dehydration process accordingto FIG. 4A for a fluid stream comprising 80% CO₂ and 20% H₂S;

FIGS. 5A and 5B are schematics of an isenthalpic dehydration processaccording to FIGS. 4A and 4B incorporating a heat exchanger for heatinga partially expanded slipstream for preventing hydrate formation in themain process feed stream prior to further expansion of the slipstream toachieve the desired temperature reduction;

FIGS. 6A and 6B are schematics of an isenthalpic dehydration processaccording to FIGS. 4A and 4B, incorporating a low temperature separatorfor removing water from the fluid stream prior to the reintroduction ofthe slipstream thereto and continuous hydrate inhibitor injection;

FIG. 7 is a schematic of a multi-stage isenthalpic process according toan embodiment of the invention;

FIG. 8 is a schematic of a multi-stage isentropic process according toan embodiment of the invention wherein one of the Joule-Thomson valvesis replaced with an isentropic fluid expander;

FIG. 9 is a schematic illustration of a further embodiment of thepresent invention; and

FIG. 10 is a schematic illustration of yet another variation of thetechnology embraced by the present invention.

The examples provided assume steady state performance. Otherconsiderations are addressed to accommodate start up, in service upsets,and shut down for commercial operations. One simple example is thatduring the first few minutes of start up, and during periods of externalprocess upsets, the temperatures and slipstream flow rates may not be atthe steady state operating condition dictated by the process design.Hydrates could potentially start forming without the provision ofsomething in the design to mitigate this condition. Embodiments of theinvention are therefore designed to include the capability of adding athermodynamic hydrate inhibitor, such as methanol, for temporaryprotection against hydrate formation in an unsteady state performance.

Similar numerals used in the Figures denote similar elements.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Embodiments of the invention take advantage of the thermodynamicproperty of typical acid gases that make them useful as a ‘refrigerant’.Such gases exhibit a relatively large temperature reduction for a givenpressure reduction within the operating region of the process. The largedecrease in temperature is used to cool a slipstream of the feed streamwhich is thereafter recycled upstream for cooling the feed stream. Inthis manner, the method uses recycling to “auto-refrigerate”. TheJoule-Thomson effect is achieved by allowing the gas to expandisenthalpically through a throttling device, typically a control valve.No external work is extracted from the gas during the isenthalpicexpansion. The rate of change of temperature with respect to pressure ina fluid is the Joule-Thomson (Kelvin) coefficient. For example, theJoule-Thomson (JT) Coefficient for carbon dioxide at 50° C. and 60 atm.is about 5.6 times greater than that of nitrogen at the same conditions.Therefore the temperature reduction for CO₂ would be about 5.6 timesgreater than for nitrogen for the same reduction in pressure at theseconditions. JT Coefficient data is also available for H₂S, SO₂ and otheracid gases, as well as for hydrocarbons, and inert gases, such asnitrogen and oxygen, that may be encountered.

Acid gases processed for commercial applications, such as Enhanced OilRecovery (EOR) applications, or Carbon Capture and Sequestration (CCS)applications are normally compressed to super-critical pressures,commonly referred to as “dense phase”, for transportation and/orsequestration. To reach dense phase, compression is normallyaccomplished in more than one stage, whether utilizing centrifugal,reciprocating, or shock compression, depending upon the initialpressure. The pressure differential between stages provides anopportunity to take advantage of the favourable JT Coefficientproperties of the vapour.

Compression is broken into two distinct regions with respect to thecritical point of the fluid being compressed. The stages of compressionin the first region are sub-critical and the stages in the second regiontake the fluid above it's critical pressure and may be accomplished bycompression and pumping means. An inlet stream enters the first regionof compression, which is sub-critical, and is assumed to be watersaturated. Some water is naturally removed by compression through thevarious stages in the first region.

In embodiments of the invention, a slipstream of fluid from theafter-cooled discharge of one stage of compression, typically near orabove critical pressure, is expanded to the suction pressure of thatsame stage, or to a preceding stage should additional temperaturereduction be required. The resulting reduced temperature of the expandedslip stream is used to cool the upstream main fluid stream, firstly byheat exchange, if required, and finally by direct mixing of theslipstream with the main fluid stream. The resulting reduction intemperature of the mixed stream condenses additional water from the gas.The amount of cooling required is a function of the minimum watercontent required for the stream composition to meet the design criteriafor water dew point temperature and/or hydrate formation temperature.

The following are examples illustrating embodiments of the invention,more particularly:

Example 1—a basic embodiment;

Example 2—utilizing a low temperature separator vessel (LTS);

Example 3—incorporating a heat exchanger (HEX);

Example 4—a multi-stage isenthalpic embodiment; and

Example 5—a multi-stage isentropic and isenthalpic embodiment.

Examples 1-3 are shown using different stream compositions; moreparticularly a stream having 100% CO₂ and a stream having 80% CO₂ and20% H₂S. It will be noted however that embodiments of the invention areapplicable to streams having varying amounts of H₂S and including SO₂,NO_(x) and any other gaseous mixtures with relatively large JTCoefficients.

Examples 4 and 5 illustrate the low temperature capabilities ofembodiments of the invention as well as the differences betweenisenthalpic and isentropic processes.

Example 1—Basic

Having reference to FIGS. 4A and 4B, in an embodiment of the invention,a water saturated acid gas feed stream 10 enters a suction stage 12where it is compressed 14 to the suction pressure of the next stage 16.The hot compressed vapour 14 is cooled 18 with an after-cooler 20resulting in the condensation of some of the water and othercondensables in the feed stream. The condensed liquid containing wateris removed 22 in a separator 24 upstream of the final stage ofcompression. The saturated gas 26 from the separator 24 is furthercompressed at 28 and is after-cooled again at 30.

A slipstream 32 from the compressed and after-cooled fluid stream isremoved and isenthalpically expanded 34 across a Joule-Thomson valve(TCV) 36 to the lower suction pressure of the same stage 16 ofcompression. The expansion results in a temperature reduction, themagnitude of which is dependent upon the magnitude of the pressurereduction and the composition of the fluid stream. The colder stream 38is combined with the after-cooled stream 18, exiting the previous stageof compression, resulting in a combined stream 40 having a temperaturereduced sufficiently to condense the required amount of water.

As shown in FIG. 4A for a feed stream having 100% CO₂, the temperatureis reduced to about 87° F. and the final water content is reduced toabout 73 lb/MMscf to result in a hydrate formation temperature (HFT) of30° F.

Referring to FIG. 4B, wherein the feed stream contained 80% CO₂ and 20%H₂S, the temperature need only be reduced to about 93° F. for a finalwater content of about 89 lb/MMscf to achieve the same hydrate formationtemperature (HFT) of 30° F.

Example 2—Heat Exchanger (HEX)

In cases where the composition of the feed stream, in combination with alarge pressure reduction, creates a stream temperature which is belowthe hydrate formation temperature of the main undehydrated feed stream,the embodiment shown in FIGS. 4A and 4B can be modified to include aheat exchanger (HEX).

In reference to FIGS. 5A and 5B, the basic embodiment is modified so asto avoid the need for continuous injection of hydrate inhibitor, as isutilized in conventional refrigeration processes.

In FIGS. 5A and 51, the slipstream 34 is partially expanded 42 across asecond Joule-Thomson Valve (JTV) 44. The temperature of the partiallyexpanded stream is thereafter raised in a heat exchanger 46 prior tofurther expansion of the stream 48 across the Joule-Thomson Valve (TCV)50. Thus, the temperatures of the partially and fully expanded streams42, 48 are maintained above the respective hydrate formationtemperatures of the main undehydrated feed stream.

For the purposes of Example 2, the design hydrate formation temperaturewas set at 15° F.

As shown in FIG. 5A, for a feed stream having 100% CO₂, the temperaturemust be reduced to about 73° F. to result in a final water content ofabout 51 lb/MMscf to achieve the design hydrate formation temperature of15° F.

With reference to FIG. 5B, and in the case where the feed streamcomprises 80% CO₂ and 20% H₂S, the temperature was reduced to about 79°F. to result in a final water content of about 64 lb/MMscf to achievethe design hydrate formation temperature of 5° F.

Example 3—Low Temperature Separator (LTS)

Referring to FIGS. 6A and 6B, an embodiment of the invention utilizes anadditional separator where temperature reduction is significant, as analternate to the embodiment described in Example 2.

As shown in FIGS. 6A and 6B, the 46 and JTV 44 of FIGS. 5A and 5B arereplaced with a second low temperature separator (LTS) 52. A slipstream54 is expanded 56 across a Joule-Thomson Valve (TCV) 44. The firstseparator 24 is positioned to remove as much water as possible from thefeed stream prior to the reintroduction of the expanded slipstream 48.The addition of hydrate inhibitor into the expanded slipstream 48 isconsidered when the process design requires that the temperature of theexpanded slipstream be below 32° F. The early removal of the waterreduces the amount of cooling required to meet the design conditionsand, should conditions warrant, reduces the amount of hydrate inhibitorrequired.

The design hydrate formation temperature for Example 3 was set at 0° F.

As shown in FIG. 6A, where the feed stream comprises 100% CO₂, thetemperature had to be reduced to 62° F. to result in a final watercontent of about 36 lb/MMscf to meet the design hydrate formationtemperature of 0° F.

With reference to FIG. 6B, where the feed stream comprises 80% CO₂ and20% H₂S, the temperature had to be reduced to about 67° F. to result ina final water content of about 45 lb/MMscf to achieve the design hydrateformation temperature of 0° F.

Example 4—Multi-Stage Isenthalpic

In reference to FIG. 7, a multi-stage embodiment of the invention isemployed where the required temperature reduction is very large. Theembodiment was designed to achieve a hydrate formation temperature of−45° F.

As shown in FIG. 7, this embodiment comprises a heat exchanger 46, a lowtemperature separator 52 and continuous hydrate inhibitor injection 56.The first separator 24 is positioned between the heat exchanger 46 andthe reintroduction of the temperature reduced stream. The early removalof water from the feed stream reduces the amount of cooling and hydrateinhibitor required to meet the design criteria.

To obtain a lower temperature, the pressure reduction which results fromthe expansion of the slipstream 58 through the Joule-Thomson Valve 44occurs over at least two stages of compression. Thus, the partiallyexpanded slipstream 60 is heated at the heat exchanger 46 and fullyexpanded 62 through the Joule-Thomson Valve 64 to be reintroduced, alongwith the injection of hydrate inhibitor, to the feed stream two or morestages 66, 68 upstream from the removal of the slipstream 58 for coolingthe feed stream 28. Condensed water is removed from the cooled feedstream 28 at the second separator 52 prior to further compression of thecooled feed stream 28.

In this example, the low temperature achieved at the fully expandedslipstream 56 and the cooled feed stream 28 necessitates the addition ofthe hydrate inhibitor, however the amount of hydrate inhibitor isminimized as a result of the upstream removal of a significant portionof water at the first separator 24.

An additional benefit of the low temperature achieved at the cooled feedstream in this example, is the ability to reduce the number ofcompression stages from five stages to four stages, resulting in areduction in the overall cost.

Example 5—Multi-Stage Isentropic

With reference to FIG. 8, a multi-stage embodiment of the inventionutilizes an isentropic fluid expander 66, such as a conventionalradial-expansion turbine or turbo-expander (such as is available fromMafi-Trench, Santa Maria, Calif., USA) to replace the Joule-ThomsonValve 44 of FIG. 7 for expansion of the slipstream 58.

In this embodiment, the isentropic fluid expander is capable ofachieving a lower temperature in the expanded slipstream 60 than ispossible using a Joule-Thompson valve (isenthalpic expansion) for thesame reduction in pressure. Additionally, the slipstream fractionrequired is smaller than it is in Example 4.

The power requirements for Stage 3 (66) and Stage 4 (68) for thisembodiment, compared to that in Example 4, are lower by about 2%. Theisentropic fluid expander produces power, about 1.8% of Stage 3 (66) andStage 4 (68) for other uses. Further, the hydrate inhibitor requirementsare minimized.

The embodiments of the invention, described herein have notableadvantages over and differences from conventional liquid desiccant andisenthalpic refrigeration dehydration processes.

In comparison to liquid desiccant dehydration processes, embodiments ofthe invention permit elimination of conventional dehydration equipmentby replacement with the expansion valves (TCV, JTV) at a small fractionof the capital cost of the conventional dehydration equipment.

In comparison to conventional isenthalpic expansion refrigerationprocesses, such as a “Choke Plant” or “DPCU”, embodiments of theinvention may permit elimination of one stage of compression, a maingas-gas heat exchanger and the addition of hydrate inhibitor, providinga significant reduction to the capital cost.

The prior art “Choke Plant” or “DPCU” requires that the entire gasstream be over-compressed and expanded to the design pressure. Thistypically increases the original compression power requirements of thesystem by 20% to 25%. Depending upon the composition of the gas and theoperating conditions, the higher compressor discharge pressure maynecessitate the addition of an entire stage of compression.

The cooling slipstream is typically 10% to 30% of the combined streamflow through a single stage, depending upon the composition of the acidgas and the required operating conditions. The increase in throughputthrough one stage of compression theoretically increases the totalcompression power demand by 2% to 6% (i.e. ⅕ of 10%-30% for a 5 stagecompressor). In comparison however, this increase is often comparable tothe increase due to the pressure drop through conventional dehydrationequipment. Further, there is an efficiency improvement, and therefore acorresponding reduction in compression power, resulting from the reducedoperating temperature of the compressor. In some instances, thecompression power requirements end up being less than when usingconventional dehydration equipment.

Lower suction temperatures, enabled by embodiments of the invention,have an additional advantage over both the conventional dehydrator andthe choke plant. The reduced temperature in one stage provides theopportunity to rebalance the compression ratios on each stage, a highercompression ratio where the suction pressure is cooler thus enabling areduction of the compression ratio in the others, until the dischargetemperatures of each stage are relatively equal at some new lower value.The reduction in discharge temperature somewhat reduces the additionalpower demand arising from the additional slipstream volume seen in oneor more stages of compression. The temperature reduction also results inlonger valve life, increased operational time and lower maintenancecosts. The rebalancing can, at some point, with lower temperatures, besignificant enough to eliminate an entire stage of compression and thusprovide considerable capital cost saving.

It is believed that the overall carbon footprint of embodiments of theinvention is significantly lower than conventional methods. Therequirement for equipment is considerably smaller reducing demand formanufacture, there is no need for the formulation of glycol and noadditional utilities are required that produce CO₂, all of which morethan offset the marginal increase in power required (typically about 2%)to compress the slipstream volume. Additionally, the lack of chemicalrequirements in embodiments of the invention significantly reducesecological risk.

Acid gases including CO₂, H₂S, SO₂, and NO_(x) are fluids well suited tothe embodiments of the invention. It is believed however that the fluidsare not limited to those disclosed herein. It is further believed thatthe thermodynamic principles utilized in embodiments of the inventionare valid for all fluid mixtures exhibiting a positive Joule-Thomson(JT) Coefficient within the desired range of process conditions; inother words, the fluid mixtures cool when expanded. As a generalization,a fluid with a larger JT Coefficient will get colder than one with asmaller JT Coefficient and therefore will require less of the fluid tobe slipstreamed. A low slip stream requirement is economicallydesirable.

Applications for embodiments of the invention lie in carbon capture andstorage (CCS), the treatment of CO₂, SO₂, and NO_(x) captured fromcombustion, gasification and industrial chemical processes forsequestration, and in AGI (acid gas injection) where H₂S and (CO₂ arecaptured from oil and gas processes for sequestration. Anotherapplication for embodiments of the invention appears in the recovery ofhydrocarbon liquids from relatively high acid gas content solution gasvapours that are typically processed in Enhanced Oil Recovery (EOR)applications. A further application for embodiments of the invention liein situations where acid gas dehydration is required in situations withminimal available space or where there is a weight restriction. Suchsituation might occur in offshore floating production operations or inretrofit applications, both onshore and offshore. The configurations ofthis invention provide a significant space and weight advantage overother commercial dehydration means.

Examples 1-5 provided herein are based upon a single set of conditions.Embodiments of the invention require optimization for each fluid and setof conditions. Optimization involves the selection of the stage ofcompression best suited for initiation of the slipstream and which isbest suited for recombining the slipstream. Another optimization lies inthe selection of the optimum variation of the process whether it beBasic, HEX, LTS, Multi-Stage, Multi-Stage Isentropic, or some othercombination of those described above. Also within any of the choices,the optimum instrumentation and control system needs to be included andthe optimum operating points for the application established.

Referring to FIG. 9, numeral 80 denotes common upstream operations withnumeral 81 denoting the overall schematic process according to a furtherembodiment.

With respect to the common numerals from the previous embodiments, aseparator 13 is provided for separating a feed into saturated gas feedstream 10 which enters compressor 12 where it is compressed to thedischarge pressure, compressed vapor 14 is then introduced intoafter-cooler 20 which results in the condensation of some of the waterand other condensables in the feed stream. These unit operations havebeen discussed herein and previously with respect to the otherembodiments.

In respect of the newly presented schematic upstream acid gas stream 18which is typically from a compressor, well, etc. is normally saturatedwith water. As an example, the stream may contain 100% acid gases orsome other concentration of acid gases with the balance typically beinghydrocarbons and low concentrations of other inert gases. For purposesof explanation, the stream may be at for example, 120° F. at a pressureof 600 psi. In this circuit, a pair of heat exchangers 84 and 86 areprovided. In terms of the heat exchangers 84 and 86, heat exchanger 84is a gas-liquid heat exchanger which is used to transfer heat in fluid18 to the cold liquid fluid 96. Stream 90 mixes with the cooled stream89 exiting the Joule-Thomson valve 44. The two are mixed in mixingdevice 92. The so formed mixture 93 at a temperature of approximately50° F., is passed into low temperature separator 94. At this point, theliquids that condense at the 600 psi pressure form a cold liquid stream96. Stream 96 will be close to the hydrate formation temperature of themixture of fluids. If the stream were further depressurized this wouldmost certainly result in the formation of a hydrate. Stream 96 passesinto heat exchanger 84, exchanges heat with, stream 18 thereby coolingstream 18 and warming stream 96. It is advantageous for stream 96 toreceive some heat from stream 18 to reduce the probability of hydrateformation. It is also advantageous to cool stream 18 to reduce theamount of additional cooling required. Once stream 96 is warmed via heatexchange through exchanger 84, stream 98 is possibly at a temperature of120° F. The pressure of stream 98 can then be reduced in valve 100without hydrate formation, to maintain a desired liquid level in the lowtemperature separator 94. As the liquid level builds, valve 100 opensand allows a stream 102 to pass into a three phase separator 104. Stream102 is possibly comprised of three phases; vapor, hydrocarbon liquid,and water. The residence time in the separator 104 is sufficient tofacilitate the separation of heavier liquids at 106, typically water,vapor at 108 and lighter liquids at 110, typically hydrocarbons. At thispoint, the separated hydrocarbon liquids 110 can be then directed to anoil treating facility for treatment (not shown), stabilization, andeventual sale.

Returning to the low temperature separator 94, the stream 112 exitingsame is a cold acid gas (typically CO₂) vapor stream and can be used asan additional source for pre-cooling the main system. Streams 88 and 112are passed into the heat exchanger 86 which, in this case is a gas-gasheat exchanger used to transfer the heat in stream 88 to the cold vaporstream 112 exiting the low temperature separator 94. This also pre-coolsstream 90 exiting the exchanger 86 thereby reducing the amount ofadditional cooling required. The stream 114 at this point has atemperature of approximately 110° F. from the example noted herein. Thissystem is particularly beneficial in that it allows for hydrocarbonrecovery where it is economically feasible.

Stream 114 is then passed into the unit operations that have beendescribed herein previously with respect to the basic overall system.

In the event that there is no possibility, or where it is noteconomically feasible to recoverliquid hydrocarbons, then the designerwould employ the system shown in FIG. 10 to be discussed in greaterdetail herein after. This is also an attractive system for retrofitapplications which could use existing compressor arrangements withminimal modifications while also benefiting from the technology setforth herein.

In an EOR application where CO₂ is utilized, make-up or additional CO₂is usually mixed with the produced vapor and reinjected into theproducing reservoir. Depending upon the pressure of the make-up CO₂stream, it may be mixed with or even replace stream 34 to improve theJoule-Thomson coefficient and to reduce the HFT. The dry, make-up CO₂could be used to minimize or eliminate usage of hydrate inhibitors, suchas methanol or glycol, during system start up. The process may bedesigned to condense fluids other than the hydrocarbons used in thisexample if so desired.

Additional stages of pressure reduction and separation (duplicating 100,102 and 104 with 110 replacing 98) may be considered if improvedhydrocarbon liquid/vapor separation efficiency is required.

Further, the system may include thermodynamic simulation software toassist in optimizing operating points by predicting water dew point,hydrate formation temperature, and hydrocarbon recovery.

Turning to FIG. 10, shown is a further embodiment of the presentinvention. In this embodiment, it is evident that a significant numberof unit operations have been removed relative to that which is shown inFIG. 9. The use of the three phase separator 104 from FIG. 9 isunnecessary in this embodiment as is the gas-liquid heat exchanger. Theremaining unit operations are similar to the functioning of operationsin FIG. 9 and the overall sequence will be apparent to one skilled inthe art.

This embodiment is particularly well suited for existing arrangementswhere a retrofit is possible to take advantage of the benefits of thesystem described herein. With the inclusion of the gas-gas heatexchanger, the cooling slipstream is typically reduced to 4% to 10% ofthe combined stream flow through a single stage, depending upon thecomposition of the acid gas and the required operating conditions. Theincrease in throughput through one stage of compression theoreticallyincreases the total compression power demand by 1% to 2% (i.e. ⅕ of4%-10% for a 5 stage compressor). The addition of the LTS is onlyrequired where the metallurgy of the existing suction scrubber is notcompatible with the acidic water produced and it is deemed inappropriateto replace the existing scrubber. The capital cost of this embodiment isincreased accordingly.

In the embodiment shown in FIG. 10, the heavy liquid phase stream 34 inthis instance is typically a warm high pressure recycle stream which istypically super critical (dense phase) or liquid. This is passed intothe Joule-Thomson valve 44 which reduces the pressure and therefore thetemperature of the stream 34. Cold low pressure recycle stream 89 isused for mixing with the pre-cooled inlet stream 90 into the mixingdevice 92.

The mixture, as previously discussed with respect to FIG. 9, is denotedby numeral 93. The liquid phase leaving the low temperature separator 94at 96 is predominantly water. This stream is typically blended elsewhereinto a water treatment process.

As an example, stream 90 may be cooled to approximately 60 to 70° F.depending on how much surface area is available in the heat exchanger86. The slipstream 34 (as discussed herein previously with respect tothe other embodiments) may be at 120° F. and possibly at 2,000 psig.This high pressure stream may be depressured in a Joule-Thomson valve44. Here it is depressured to approximately the same pressure (600 psig)as stream 90. As a result of passing through the Joule-Thomson valve,the stream is expanded and thus cools to approximately 40° F. forpurposes of this example. The resulting cold stream 89, is mixed withstream 90 in mixing device 92. The so formed mixture 93 at a temperatureof approximately 50° F., is passed into low temperature separator 94. Atthis point, the liquids that condense at the 600 psi pressure form acold liquid stream 96. The stream 112 exiting separator 94 is a coldacid gas (typically CO₂) vapor stream and can be used as a source forpre-cooling the hot inlet stream 18. Streams 18 and 112 are passed intothe heat exchanger 86 which is a gas-gas heat exchanger used to transferthe heat from stream 18 to the cold vapor stream 112 from the lowtemperature separator 94. This heal exchange also pre-cools stream 90exiling the exchanger 86 thereby reducing the amount of additionalcooling required. The stream 114 at this point has a temperature ofapproximately 110° F. from the example noted herein.

We claim:
 1. A method for removing condensable components from a fluidcontaining said condensable components, comprising: Optimizing thetemperature of an initial feed stream including said condensablecomponents through heat exchange and cooling to condense liquids therefrom and removing said liquids to form a gas stream; The gas stream isthen compressed and after-cooled to form a high pressure stream; Aportion of the high pressure stream is expanded to form a cooled lowpressure stream which is mixed with said initial feed stream to augmentcooling and condensation of condensable components in the initial feedstream.
 2. The method as set forth in claim 1, including the step ofdetermining the hydrocarbon and water content of said initial feedstream.
 3. The method as set forth in claim 1 or 2, wherein said heatexchange includes sequential, heat exchange in a plurality of heatexchangers for optimizing energy retention in said stream and reducingthe quantity of recycle.
 4. The method as set forth in any one of claims1 through 3, wherein said heat exchanger includes a plurality ofparallel heat exchangers for optimizing energy retention in said streamand reducing the quantity of recycle.
 5. The method as set forth inclaim 3, wherein said step of optimizing said energy includes operatingthe method at a temperature range outside that where hydrates form. 6.The method as set forth in any one of claims 1 through 5, wherein saidheat exchange is conducted through a gas-liquid heat exchange operation.7. The method as set forth in any one of claims 1 through 6, whereinsaid heat exchange is conducted through a gas-liquid heat exchangeoperation in sequence with a gas-gas heat exchange operation.
 8. Themethod as set forth in any one of claims 1 through 7, wherein said heatexchange is conducted through a gas-liquid heat exchange operation inparallel with a gas-gas heat exchange operation.
 9. The method as setforth in any one of claims 1 through 8, wherein said heat exchange isconducted through a gas-liquid heat exchange operation.
 10. The methodas set forth in any one of claims 1 through 9, further including thestep of treating said feed stream to a water content reduction unitoperation.
 11. The method as set forth in claim 6, further includingrecovering hydrocarbons from the stream produced from said method. 12.The method as set forth in any one of claims 1 through 11, furtherincluding recovering acid gas components from the stream produced fromsaid method.
 13. The method as set forth in claim 10, further includingrecycling said acid gas components.
 14. The method as set forth in anyone of claims 1 through 13, wherein the fluid has a positiveJoule-Thomson coefficient.
 15. The method as set forth in any one ofclaims 1 through 14, wherein said condensable components include C₃H₁₂and heavier hydrocarbons.
 16. The method as set forth in any one ofclaims 1 through 15, further including an optional step of addinghydrate inhibitor to said fluid.
 17. The method as set forth in claim16, wherein said hydrate inhibitor is methanol.